Hydrocarbons sometimes exist in a formation but cannot flow readily into the well because the formation has very low permeability. In order for hydrocarbons to travel from the formation to the wellbore there must be a flow path from the formation to the wellbore. This flow path is through the formation rock and has pores of sufficient size and number to allow a conduit for the hydrocarbons to move through the formation. In some subterranean formations containing hydrocarbons, the flow paths are of low incidence or occurrence and/or size that efficient hydrocarbon recovery is hampered.
With respect to wells that previously produced satisfactorily, a common reason for a decline in oil and gas production from a particular formation is damage to the formation that plugs the rock pores and impedes the flow of oil to the wellbore and ultimately to the surface.
Well stimulation refers to the various techniques employed to improve the permeability of a hydrocarbon-bearing formation. Three general well-stimulation techniques are typically employed. The first involves injecting chemicals into the wellbore to react with and dissolve permeability damaging materials such as wellbore coatings, e.g. as may remain from previously used drilling fluids. A second method requires injecting chemicals through the wellbore and into the formation to react with and dissolve small portions of the formation thereby creating alternative flow paths for the hydrocarbons to flow to the wellbore. These alternative flow paths redirect the flow of hydrocarbons around the low permeability or damaged areas of the formation. A third technique, often referred to as fracturing, involves injecting chemicals into the formation at pressures sufficient to actually fracture the formation, thereby creating a large flow channel though which hydrocarbon can more readily move from the formation and into the wellbore.
Acidizing treatments of wells are a conventional process for increasing or restoring the permeability of subterranean formations so as to facilitate the flow of oil and gas from the formation into the well. The acid treatment is to remove formation damage along as much of the hydrocarbon flow path as possible, and/or to create new flow paths. An effective treatment should remove as much damage as possible along the entire flow path. This process involves treating the formation with an acid to dissolve fines and carbonate scale plugging or clogging the pores, thereby opening the pores and other flow channels and increasing the permeability of the formation. Continued pumping forces the acid into the formation, where it etches channels or wormholes. These channels provide ways for the formation hydrocarbons to enter the well bore.
Conventional acidizing fluids, such as hydrochloric acid or a mixture of hydrofluoric and hydrochloric acids, have high acid strength and quick reaction with fines and scale nearest the well bore, but have a tendency to corrode tubing, casing and down hole equipment, such as gravel pack screens and down hole pumps, especially at elevated temperatures. In addition, above 200° F. (92° C.), HCl is not recommended because of its destructive effect on some rock matrices. Due to the type of metallurgy, long acid contact times and high acid sensitivity of the formations, removal of the scale with hydrochloric acid and hydrochloric acid mixtures has been largely unsuccessful. There is a need to find an acid fluid system to dissolve the scale and remove the source of the fines through acidizing the surrounding formation and not damage the downhole equipment, particularly for high temperature wells.
The thickened acid fluids also have applications in hydraulic fracturing and in other well stimulation techniques known to one of ordinary skill in the art. Hydraulic fracturing is a method of using pump rate and hydraulic pressure to fracture or crack a subterranean formation. Once the crack or cracks are made, high permeability proppant, relative to the formation permeability, is pumped into the fracture to prop open the crack. When the applied pump rates and pressures are reduced or removed from the formation, the crack or fracture cannot close or heal completely because the high permeability proppant keeps the crack open. The propped crack or fracture provides a high permeability path connecting the producing wellbore to a larger formation area to enhance the production of hydrocarbons. When an acid is used in the fracturing fluid to increase or restore permeability to the formation, the treatment is term “acid fracturing” or “acid frac”.
A successful acid treatment includes uniform placement of fresh acid fluids on the desired area. Chemical diverting agents attempt to temporarily block the high permeability interval or area and divert the fresh acid fluids into the desired low permeability or damaged intervals or areas. Conventional chemical diverters may be benzoic acid flakes, resins, and the like. More than two sequential stages composed of acid fluids followed by foamed or viscous acid diverter fluids have also been used to more uniformly distribute the fresh acid fluids in the hydrocarbon producing formation. Foamed diverter fluids are typically brines, such as 3% bw ammonium chloride brine, containing up to 2% by high-foaming surfactant and possibly other additives. Viscous diverter fluids are typically brines that contains polymer to thicken the brine, such as hydroxyethylcellulose (HEC). The use of diverting agents and diverter fluids has shown favorable results, however in many cases their efficiency in diverting acid can be poor and there can be problems cleaning-up the diverter from the treated reservoir. There is still a need for new methods for diverting acid fluids that are robust in performance and less problematic during cleanup.
Recently it has been discovered that aqueous drilling and treating fluids may be gelled or have their viscosity increased by the use of non-polymeric viscoelastic surfactants (VES). These VES materials are in many cases advantageous over the use of polymer gelling agents in that they are comprised of low molecular weight surfactants rather than high molecular polymers whereby polymer accumulations (e.g. polymeric filtercake) can be avoided. Viscoelastic type surfactants generate viscosity in aqueous fluids by forming unique elongated micelle arrangements. These unique arrangements have often been referred to as worm-like or rod-like micelles structures. However, VES gelled aqueous fluids may exhibit very high viscosity at very low shear rates and under static conditions. The exceptionally high viscosity, often in thousands of centipoise, can make the VES gelled fluid very difficult to initially move and displace from the pores and fractures of the formation. While the very high viscosity at very low shear rate may be good for diverting acid fluids, this in turn makes VES fluids hard to cleanup. The appearance of a VES gelled aqueous fluid at static to low shear conditions is shown in FIG. 1.
However, little progress has been made toward developing internal breaker systems for the non-polymeric VES-based gelled fluids. To this point, VES gelled fluids have relied only on “external” or “reservoir” conditions for viscosity reduction (breaking) and VES fluid removal (clean-up) during hydrocarbon production. Additionally, over the past decade it has been found that reservoir brine dilution has only a minor, if any, breaking effect of VES gel within the reservoir.
Instead, only one reservoir condition is primarily relied on for VES fluid viscosity reduction (gel breaking or thinning), and that has been the rearranging, disturbing, and/or disbanding of the VES worm-like micelle structure by contacting the hydrocarbons within the reservoir, more specifically contacting and mixing with crude oil and condensate hydrocarbons, as described in the U.S. Pat. No. 5,964,295. In one non-limiting embodiment, it is believed that the gel or increased viscosity is imparted to the aqueous fluid by the worm-like or rod-like micelles become entangled with one another, as illustrated in FIG. 2, where 10 refers to the worm-like or rod-like micelles and 12 refers to the individual surfactant molecules where the polar head groups on the micelle surface are represented by the individual spheres and the hydrophobic tails are directed or oriented into the interior of the micelle.
However, in many gas wells and in cases of excessive displacement of crude oil hydrocarbons from the reservoir pores during a VES gel treatment, results have shown many instances where VES fluid in portions of the reservoir are not broken or are incompletely broken resulting in residual formation damage (hydrocarbon production impairment). Contacting and breaking the viscous micelle-based fluid by reservoir hydrocarbons in all parts of the reservoir is not always effective. One viable reason is the exceptionally high viscosity VES fluid can exhibit at very low shear rates and static conditions which makes the fluid difficult to move and remove from porous media (i.e. the pores of the reservoir). Hydrocarbon producing reservoirs typically have heterogeneous permeability, where VES fluid within the less permeable portions of the reservoir may be even more difficult to move and cleanup. The very high viscosity at very low shear rates can prevent uniform contacting and breaking of viscous VES fluid by the reservoir hydrocarbons. Channeling and by-passing of viscous VES fluid often occurs that results in impaired hydrocarbon production. In such cases post-treatment clean-up fluids composed of either aromatic hydrocarbons, alcohols, surfactants, mutual solvents, and/or other VES breaking additives have been pumped within the VES treated reservoir in order to try and break the VES fluid for removal. However, placement of clean-up fluids is problematic and normally only some sections of the reservoir interval are cleaned up, leaving the remaining sections with unbroken or poorly broken VES gelled fluid that impairs hydrocarbon production. Because of this phenomenon and other occasions where reliance on external factors or mechanisms has failed to clean-up the VES fluid from the reservoir during hydrocarbon production, or in cases where the external conditions are slow acting (instances where VES breaking and clean-up takes a long time, such as several days up to possibly months) to break and then produce the VES treatment fluid from the reservoir, and where post-treatment clean-up fluids (i.e. use of external VES breaking solutions) are inadequate in removing unbroken or poorly broken VES fluid from all sections of the hydrocarbon bearing portion of the reservoir, there has been an increasing and important industry need for VES fluids to have internal breakers. Desirable internal breakers that should be developed include breaker systems that use products that are incorporated within the VES-gelled fluid that are activated by downhole temperature that will allow a controlled rate of gel viscosity reduction over a rather short period of time of 1 to 16 hours or so, similar to gel break times common for conventional polymeric fluid systems.
A challenge has been that VES-gelled fluids are not comprised of polysaccharide polymers that are easily degraded by use of enzymes or oxidizers, but are comprised of surfactants that associate and form viscous rod- or worm-shaped micelle structures that exhibit very high apparent viscosity at very low fluid shear rates. Conventional enzymes and oxidizers have not been found to act and degrade the surfactant molecules or the viscous micelle structures they form. It is still desirable, however, to provide some mechanism that relies on and uses internal phase breaker products that will help assure complete viscosity break of VES-gelled fluids.
It would be desirable if a viscosity breaking system could be devised to break the viscosity of fracturing and other well treatment fluids gelled with and composed of viscoelastic surfactants, particularly break the viscosity completely and relatively quickly. It would also be advantageous if a composition and method could be devised to overcome some of the problems in the conventional acidizing methods and fluids.